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SE Transformer

IN THE DISPUTE RESOLUTION PANEL AT MELBOURNE

(Constituted for a determination as to compensation under Rule 3.16.2 of the National Electricity Rules)

JOINT SUBMISSION TO THE DISPUTE RESOLUTION PANEL

The Claimants listed in Schedule 1 (Claimants)

and

Australian Energy Market Operator Limited (ABN 94 072 010 327)

(AEMO)

A. Introduction

1. The italicised terms used in this submission are defined in the National Electricity Rules (Rules).1

2. Other terms and acronyms are defined in bold where they are first used in this submission. For convenience, they are also listed in Schedule 2.

B. Application

3. The Claimants are and were, at all material times, registered as Market Generators for the generating systems listed in Schedule 1 (Generating Systems).

4. On 30 November 2015, AEMO declared that a scheduling error had occurred that affected the Generating Systems from the dispatch interval ending 0945 hr on 11 December 2014 to the dispatch interval ending 1020 hr on 29 December 2014 (Scheduling Error Period).2

5. Clause 3.16.2(a) of the Rules permits any Market Generator affected by a scheduling error to apply to the dispute resolution panel (DRP) for a determination as to compensation in respect of the scheduling error. The matters to be determined by the DRP are:

(a) whether compensation is payable;

(b) the amount of compensation to be paid to each Claimant from the Participant compensation fund;3 and

(c) the manner and timing of that payment.4

C. National Electricity Rules6. Version 66 of the Rules applied during the Scheduling Error Period.

7. The amendments made to the Rules since Version 66 do not alter the effect of the provisions cited in this submission in a manner that is material to the matters

1 Section C addresses the question of which versions of the Rules are relevant to the period during which the scheduling error impacted the Claimants.

2 AEMO may declared a scheduling error under clause 3.8.24(a)(2) of the Rules.3 Clause 3.16.2 (b) and (d).4 Clause 3.16.2(i).

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relevant to the DRP's determination of compensation as a result of the scheduling error.

D. AEMO and the National Electricity Market (NEM)8. Sections D to H set out background information regarding the operation of the NEM

and how Scheduled Generators and Semi-Scheduled Generators are dispatched in the NEM. This is included to provide context to the DRP.

9. AEMO operates and manages the NEM. The NEM is essentially two things: the physical infrastructure that keeps electricity flowing from producers to consumers, and a notional wholesale pool (or spot market) to which producers sell, and from which purchasers buy, electricity.

10. Electricity is dynamically produced to satisfy demand that varies instantaneously. The NEM facilitates the instantaneous matching of supply and demand through a centrally coordinated process managed by AEMO, called central dispatch.

11. Figure 1 depicts the relationships between different participants in the NEM.

12. The NEM is a gross pool. This means that all Generators whose power output enters the grid must 'sell' their output via the market conducted by AEMO, unless they are embedded in a distribution network and have already sold their output to the local retailer or to a consumer located at the same connection point.

13. In geographic terms, the NEM covers the supply of electricity to southern and eastern Australia. It operates on one of the world’s longest interconnected power systems, a distance of more than 4,000 kilometres.

14. The NEM is divided into five regions for market pricing purposes:

(a) Queensland;

(b) New South Wales (incorporating the Australian Capital Territory);

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(c) Victoria;

(d) South Australia; and

(e) Tasmania.

15. Each region is connected to its adjacent regions by interconnectors, which are a series of transmission lines that facilitate the flow of electricity between regions. Figure 2 shows the interconnectors:

Figure 2 – Interconnectors in the NEM

16. A number of different types of organisations can participate in the NEM. These are called Registered Participants. Some are registered in their capacity as providers of infrastructure, such as Network Service Providers (NSPs) while others participate in the wholesale electricity exchange as Market Participants, buying and selling electricity.

17. The Rules allow producers of electricity in the NEM to register in a number of different categories. For example:

(a) Scheduled Generators participate in the central dispatch process. Generally, these are Generators with generating units whose nameplate rating is greater than 30 MW.

(b) Non-Scheduled Generators are typically Generators with generating units whose nameplate rating is less than 30 MW and do not participate in the central dispatch process.

(c) Semi-Scheduled Generators are Generators in respect of which a generating unit is classified as a semi-scheduled generating unit. Typically, this occurs where:

(i) a generating unit has a nameplate rating greater than 30 MW, or a group of generating units connected at a common connection point have a combined nameplate rating greater than 30 MW; and

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(ii) the output of the relevant generating unit is intermittent (such as for wind farms).

(d) Generators that sell all of their electricity into the spot market are registered as Market Generators. Market Generators are paid the spot price applicable at their network connection for each trading interval during which they supply electricity to the market. A Generator that sells its entire output to either a Local Retailer or consumer located at the same connection point is classified as a Non-Market Generator.

E. The Regulatory Framework18. The NEM is regulated by the National Electricity Law (NEL), a schedule to the

National Electricity (South Australia) Act 1996 (SA) that applies in each of the participating jurisdictions through a co-operative legislative scheme. The Rules are made and enforced under the NEL.

19. Under the NEL, AEMO has two core functions: power system operator, and wholesale market operator.

20. As power system operator, AEMO is concerned primarily with meeting standards of security and reliability. Power system security refers to the power system's capacity to continue operating within defined technical limits even in the event of the disconnection of a major power system element, such as an interconnector or large generating unit. Power system reliability refers to the power system's capacity to supply sufficient energy to meet consumer demand.

21. As wholesale market operator, AEMO facilitates the wholesale trading of electricity through a centrally co-ordinated dispatch process (central dispatch).

F. Central Dispatch22. Central dispatch refers to the AEMO-managed process of dispatching electricity to

meet demand in accordance with Chapter 3 of the Rules.

23. Central dispatch should aim to maximise the value of spot market trading on the basis of dispatch offers and dispatch bids (that is, the lowest cost generating units needed for electricity supply to meet demand are dispatched) subject to a number of matters, such as network constraints and power system security requirements.5

24. A Generator can own one or more generating units. Unless AEMO approves an application to aggregate these into a single entity for bidding purposes, AEMO receives bids for, and then determines loading levels (dispatch instructions) on an individual generating unit basis.

25. Dispatch offers are processed by a computer system called the National Electricity Market Dispatch Engine (NEMDE).

26. NEMDE is based on a constrained optimisation program that uses linear programming techniques that represent the power system as reflected in Figure 3:

5 Clause 3.8.1(b).

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27. AEMO forecasts electricity consumption in each region, identifies the capability of each transmission network to transmit electricity and captures the present state of the power system from information provided by Transmission Network Service Providers (TNSPs). AEMO then determines the generation outputs for each Generator according to an optimisation process that is specified in the Rules and, in practice, performed by NEMDE. This process is repeated for every dispatch interval. A simplified form of this optimisation process, as it applies at a general level, is depicted in Figure 4.

28. The central dispatch process attempts to maximise the value of electricity traded and produces a dispatch price in each region that represents the marginal price of producing the next increment of electricity at that location.

G. Scheduled Generation and Central Dispatch

29. To participate in central dispatch, Scheduled Generators must submit dispatch offers to AEMO to generate electricity6. In each dispatch offer, Scheduled

6 Clause 3.8.2(a).

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Generators must make an offer to provide a certain number of megawatts (MW) of electricity for each of the 48 trading intervals in a trading day and may make offers for up to ten price bands for each generating unit.7 All prices in price bands are locked in at 12:30 EST on the day before trading commences, but MW quantities associated with those price bands can be modified at any time prior to dispatch.

30. The highest price Scheduled Generators can offer is $14,000 per MWh (market price cap) and the lowest is -$1,000 per MWh (market floor price).8 Scheduled Generators must specify other technical matters in their dispatch offers, such as their rate of change for increasing or decreasing their output in MW/minute (ramp rate).

31. AEMO sends Scheduled Generators a pre-dispatch schedule every 30 minutes. A pre-dispatch schedule is essentially a forecast that gives Scheduled Generators an indication of when they will be dispatched, and for what level of output they will be dispatched for the trading intervals in the next two days. Scheduled Generators have an opportunity to rebid the MW capacity that they can produce and other technical aspects of their capacity right up to five minutes before the event, but cannot change the prices for the price bands they have offered.

32. NEMDE sends Scheduled Generators electronic dispatch instructions to increase or reduce the quantity of electricity they produce for each dispatch interval.

33. NEMDE will process all the data it has available to achieve the lowest cost and most efficient outcome taking into account power system limitations. In general, and without considering the impact of constraints, ramp rate and other limitations for each dispatch interval, Scheduled Generators will be dispatched in ascending price band order until enough electricity has been produced to meet demand in that dispatch interval.

34. The spot price for a trading interval is the average of the six dispatch interval prices within that trading interval.

35. All of the Scheduled Generators dispatched during that trading interval will be paid the spot price times their loss factor for the energy they produced in that trading interval, even if their dispatch offers were for a lower price. Any Scheduled Generators whose offers were too expensive and were not needed to meet demand are not dispatched and, consequently, do not get paid. In this way, the wholesale exchange encourages competition between Scheduled Generators.

H. Semi-Scheduled Generation and Central Dispatch36. A Semi-Scheduled Generator must operate a semi-scheduled generating unit in

accordance with the central dispatch process under Chapter 3 of the Rules.9

37. The Rules distinguish between two different forms of dispatch interval for semi-scheduled generating units, which are treated differently in the central dispatch process:

(a) semi-dispatch intervals; and

(b) dispatch intervals that are not semi-dispatch intervals.

38. Under the Rules, a semi-dispatch interval is a dispatch interval for which either:

7 Clause 3.8.6(a).8 Clauses 3.9.4(b) and 3.9.6(b).9 Clause 2.2.7(h).

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(a) a network constraint would be violated if the semi-scheduled generating unit's generation were to exceed the dispatch level specified in the related dispatch instruction at the end of the dispatch interval; or

(b) the dispatch level specified in a dispatch instruction is less than the unconstrained intermittent generation forecast (UIGF) at the end of the dispatch interval,

and which is notified by AEMO in a dispatch instruction to be a semi-dispatch interval.

39. Semi-Scheduled Generators participate in the central dispatch process by submitting offers, but effectively operate as though they were Non-Scheduled Generators (and need not respond to dispatch instructions) unless AEMO declares a semi-dispatch interval for a semi-scheduled generating unit. During a semi-dispatch interval, the output for that semi-scheduled generating unit must not exceed a dispatch level specified by NEMDE.

40. In operating the central dispatch process under clause 3.8 of the Rules, AEMO's obligation in clause 3.8.1(b) to aim to maximise the value of spot market trading is subject to a number of matters, including, non-scheduled load requirements in each region10 and, in respect of semi-scheduled generating units, constraints identified by the UIGF.11

41. The requirement for AEMO to develop a UIGF is established in clause 3.7B of the Rules, which provides that AEMO must prepare a forecast of the available capacity of each semi-scheduled generating unit (to be known as the UIGF) for the purposes of, amongst other things, dispatch.12

I. The Scheduling Error42. Clause 3.8.24(a) of the Rules provides that a scheduling error is any one of the

following circumstances:

(a) the DRP determines under clause 8.2 that AEMO has failed to follow the central dispatch process set out in clause 3.8;13

(b) AEMO declares that it failed to follow the central dispatch process set out in clause 3.8;14 or

(c) AEMO determines under clause 3.9.2B(d) that a dispatch interval contained a manifestly incorrect input.15

43. AEMO has published a report titled ‘NEM Scheduling Error – Incorrect South East Transformer Rating in South Australia’ (Report).16 The Report describes the occurrence of the scheduling errors and a copy is provided in Schedule 3.

10 Clause 3.8.1(b)(3).11 Clause 3.8.1(b)(2)(ii).12 Clause 3.7B(a)(2).13 Clause 3.8.24(a)(1).14 Clause 3.8.24(a)(2).15 Clause 3.8.24(a)(3).16 The Report was republished in December 2016 after a number of corrections were made to the impacted

generating units.

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J. Dispatch Intervals affected by the Scheduling Error44. In its Report, AEMO confirms that the scheduling error affected a number of

dispatch intervals between 1 December 2014 and 29 December 2014 and the output of a number of Market Generators with scheduled generating units and semi-scheduled generating units during those dispatch intervals.17

K. Calculation of Compensation 45. Clause 3.16.2 of the Rules provides that where a scheduling error occurs:

(a) a Market Participant may apply to the DRP for a determination as to compensation;18 and

(b) the DRP may determine that compensation is payable to Market Participants and the amount of any such compensation payable from the Participant compensation fund.19

46. A Scheduled Generator or Semi-Scheduled Generator who receives an instruction in respect of a scheduled generating unit or semi-scheduled generating unit (as applicable) to operate at a lower level than the level at which it would have been instructed to operate had the scheduling error not occur is entitled to receive in compensation an amount determined by the DRP.20

47. The DRP must, therefore, determine the compensation payable in respect of any scheduled generating unit or semi-scheduled generating unit that, as a result of the scheduling error, was dispatched at a lower level than it would have been had the scheduling error not occur.21

48. To determine the amount of this compensation payable to a Claimant , it is necessary to establish the following values for each affected dispatch interval or semi-dispatch interval:

(a) the actual output of each Generating System;

(b) the dispatch instruction that would have been issued by AEMO in the absence of the scheduling error;

(c) the applicable intra-regional loss factor for each Generating System; and

(d) the applicable spot price.22

49. The following compensation principles have been agreed by the parties for the purposes of quantifying each Claimant’s spot market losses during affected dispatch intervals or semi-dispatch intervals (as applicable) for this scheduling error:

(a) Calculate the difference (in MWh) between the actual output of a generating unit and the output that would have occurred in the absence of the scheduling error;

(b) Multiply the quantity calculated in accordance with paragraph (a) by the intra-regional loss factor to give the compensable quantity (in MWh).

17 See Table 1 of the Report18 Clause 3.16.2(a).19 Clause 3.16.2(b).20 Clause 3.16.2(d).21 Clause 3.16.2(d)22 Clause 3.16.2(h)(3) requires the dispute resolution panel to use the spot price determined under Clause 3.9 in

determining compensation.

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(c) The spot market loss is the compensable quantity calculated in accordance with paragraph (b) multiplied by the applicable spot price.

(i) If the applicable spot price for an affected dispatch interval or semi-dispatch interval is negative, the calculation in accordance with paragraph (c) will result in a payment to the market (that is, a credit).

L. Compensation Amounts50. AEMO has calculated the amount of compensation that would be payable to each

Claimant, based on the principles in Part K.

51. The calculations are agreed by each Claimant. The total compensation due to each Claimant are set out below:

Claimant Compensation

Snowy Hydro Limited $ 50,768.74

AGL Macquarie Pty Limited $ 38,172.96

Callide Power Trading Pty Limited $ 33,432.76

Origin Energy Electricity Limited $ 24,087.98

Stanwell Corporation Limited $ 15,150.22

Hydro-Electric Corporation (Trading as Hydro Tasmania) $ 14,847.77

CS Energy $ 12,432.19

EnergyAustralia Pty Ltd $ 12,056.43

Lake Bonney Wind Power Pty Ltd $ 10,817.08

IPM Australia Limited $ 4,872.13

AGL Loy Yang Marketing Pty Ltd $ 1,378.27

EnergyAustralia Yallourn Pty Ltd $ 1,005.08

Pelican Point Power Limited $ 670.81

Milmerran Energy Trader Pty Ltd $ 655.79

AGL Hydro Partnership $ 608.30

Hazelwood Power $ 515.61

AGL SA Generation Pty Limited $ 336.68

Origin Energy Uranquinty Power Pty Ltd $ 81.72

M. Participant Compensation Fund52. AEMO is required by clause 3.16.1 of the Rules to 'maintain, in the books of the

corporation, a fund called the Participant compensation fund for the purpose of paying compensation ... as determined by the dispute resolution panel for scheduling errors…'.

53. AEMO is required to pay to the Participant compensation fund the component of Participant fees attributable to the Participant compensation fund. The overall funding requirement for each financial year is the lesser of:

(a) $1,000,000; and

(b) $5,000,000 minus the amount that AEMO reasonably estimates will be the balance of the Participant compensation fund at the end of the financial year.23

23 See clause 3.16.1(c).

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54. Any interest paid on money held in the Participant compensation fund also accrues to and forms part of the Participant compensation fund.24

Participant Fee Determination

55. AEMO must prepare and publish before the beginning of each financial year a budget of the revenue requirements for AEMO for that financial year.25 The budget must take into account and separately identify projected revenue requirements in respect of the funding requirements of the Participant compensation fund in accordance with clause 3.16.26 The projected revenue requirements in respect of the funding requirements of the Participant compensation fund must only be recovered from Scheduled Generators, Semi-Scheduled Generators and Scheduled Network Services Providers.27

56. AEMO must also develop, review and publish the structure (including the introduction and determination) of Participant fees for such periods as AEMO considers appropriate.28 The Participant fees should recover the budgeted revenue requirements for AEMO determined under clause 2.11.3.29

57. AEMO has determined the structure of Participant fees for the period 1 July 2016 to 30 June 2021.30 AEMO determined that the budgeted revenue requirements in respect of the Participant compensation fund will be allocated to Scheduled Generators, Semi-Scheduled Generators and Scheduled Network Service Providers and levied using a combination of historical capacity and historical energy scheduled, where:

(a) 50% will be collected on the basis of MWh of energy scheduled or metered in the previous calendar year; and

(b) 50% will be collected on the basis of the higher of the greatest registered capacity and highest notified maximum capacity in the previous calendar year.

58. AEMO may charge a Registered Participant the relevant components of Participant fees by giving the Registered Participant a statement setting out the amount payable by that Registered Participant and the date for payment.31 In the case of Market Participants, AEMO may, alternatively, include the relevant amount in the f inal statements described in clause 3.15.15.32 A Registered Participant must pay to AEMO the net amount stated in the relevant statement by the date specified by AEMO.33

Matters to be taken into account by DRP

59. The Participant compensation fund balance as at 15 March 2017 is $5,115,450.

24 Clause 3.16.1(e).25 Clause 2.11.3(a).26 Clause 2.11.3(b)(8).27 Clause 2.11.3(b)(8).28 Clause 2.11.1(a).29 Clause 2.11.1(b)(2).30 See http://www.aemo.com.au/Datasource/Archives/Archive595. 31 Clause 2.11.2(a).32 Clause 2.11.2(b).33 Clause 2.11.2(c).

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http://www.aemo.com.au/Datasource/Archives/Archive595

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60. As a consequence, the funding requirement for the Participant compensation fund is nil until 30 June 2017.

61. Since the commencement of the market there have been 29 payments made from the Participant compensation fund. These are as follows:

Market Participant Date of Scheduling Error Compensation

Snowy Hydro Limited 31 Oct 2005 $438,892.00

Macquarie Generation 22 Oct 2007 $4,544,638.00

AGL Hydro Partnership 19 & 20 Nov 2009 $571,935.06

Synergen Power Pty Ltd 19 May 2009 - 14 Jan 2010 $246,858.78

AGL Hydro Partnership

Infigen

Trustpower

Pacific Hydro

EnergyAustralia

Various $78,585.00

$1,178,290.00

$12,031.00

$29,999.00

$11,891.00Hydro-Electric Corporation (trading as Hydro Tasmania)AGL Loy Yang Marketing Pty Ltd CS Energy LimitedAGL Hydro Partnership Origin Energy Electricity LimitedAGL Macquarie Pty Limited Callide Power Trading Pty LimitedAGL SA Generation Pty LimitedDelta ElectricitySnowy Hydro LimitedStanwell Corporation LimitedHazelwood PowerEnergyAustralia Pty LtdAurora Energy (Tamar Valley) Pty Ltd (trading as AETV Power)Flinders Operating Services Pty LtdEnergyAustralia Yallourn Pty LtdIPM Australia Limited Braemar Power Project Pty LtdOrigin Energy Uranquinty Power Pty LtdPelican Point Power Limited

2 May 2014 - 6 Jun 2014 $296,661.14

(in total)

N. Other Applications for Compensation62. No further scheduling errors have been declared since the last payment.

63. There are three other outstanding claims for compensation in respect of four separate scheduling errors:

1. The first involves two scheduling errors were declared by AEMO as a result of incorrect UIGFs that affected a number of semi-dispatch intervals between 2012 and 2016. If all possible energy claims are accepted by the DRP, the total paid to the claimants will be $3,082,235.85.

2. The second scheduling error was declared by AEMO as a result of the application of incorrect ratings to three 66kV transmission lines in Victoria, which were then used in constraint equations that were subsequently used in central dispatch. If all submitted claims are accepted by the DRP, the total paid to the claimants will be $5,554,203.90.

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(c) The third was declared by AEMO as a result of the application of incorrect SCADA readings from Feeder 7145 in Queensland, which was then used in constraint equations that were subsequently used in central dispatch. If all submitted claims are accepted by the DRP, the total paid to the claimants will be $178,505.43.

65. Taking all claims into consideration, the total amount to be paid out of the Participant compensation fund in the current financial year will exceed the total amount currently deposited in it.

66. In making its determination, the DRP must:

(a) consider the claim for compensation by reference to the reduction in the loading level at which a generating unit operated due to the scheduling error;

(b) use the spot price determined under clause 3.9;34

(c) take into account the current balance of the Participant compensation fund and the potential for further liabilities to arise during the year;35 and

(d) recognise that the aggregate liability in any year in respect of scheduling errors cannot exceed the balance of the Participant compensation fund that would have been available at the end of the year if no compensation payments for scheduling errors had been made during that year.36

67. In a decision of the DRP dated 24 April 2008 in a claim for compensation from the Participant compensation fund by Macquarie Generation, it was held that the reference to 'the potential for further liabilities to arise during the year' in clause 3.16.2(h)(4) is a reference to 'the possibilities of further actual liabilities during the financial year' that will have created a clear balance in the Participant compensation fund.37 The DRP also accepted that the reference to 'year' in clause 3.16.2(h) is a reference to a financial year.38

68. In a decision of the DRP dated 9 November 2016, the DRP described the further liabilities referenced in clause 3.16.2(h)(4) as 'future contingent liabilities'. Specifically in reference to a claim for compensation for losses arising from the AWEFS scheduling error, the DRP commented that the impending claim had been advised to the WEMDRA and was well known to the market. The DRP stated: 'it is more likely than not that the wind scheduling error matter will result in a liability to be met by the Participant compensation fund; and while the timing is unclear the liability may crystallise before 30 June 2017'. 39

O. The Need for Apportionment

69. There are insufficient funds in the Participant compensation fund to cover all current claims for compensation, let alone any prospective claim.

70. Full payment of the loss of the Claimants should not be made, as this would defeat all known other known claims for compensation that would be payable by the end of the current financial year.

34 Clause 3.16.2(h)(3)35 Clause 3.16.2(h)(4).36 Clause 3.16.2(h)(5).37 See paragraphs 24 and 25 of the decision.38 See paragraph 15 of the decision. 39 See paragraph 41 of the decision.

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71. A more equitable distribution of the balance of funds in the Participant compensation fund is necessary so as not to defeat the spirit of clause 3.16.2(h) of the Rules.

72. The DRP must consider how to allocate available funds.

73. Most of the case law around the distribution of limited funds to claimants with claims that, in total, exceed the balance of available funds are in the areas of insolvency, 40 or breach of trust41, but only a limited sub-set of these would appear to have any application in the present circumstances.

74. Of these, the parties submit that the more appropriate ones are the following:

(a) Pari passu, or on a pro rata basis – the advantage of this type of allocation is that each Claimant receives some compensation based on the following formula:

C∗BS

Where: C = the amount of compensation sought by a Claimant

B = the balance in the Participant compensation fund

S = Sum of all amounts of compensation sought by all Claimants plus all claimants involved in the claims detailed in paragraph 64.

(b) On a first-in, first-out basis – this involves payments being made in chronological order, namely, on the basis of which application was made the earliest, until the Participant compensation fund is exhausted.

75. Australian case law suggests that the pari passu rule is the preferred mode of allocating funds.42

P. Costs76. For the purposes of this claim, the costs of these proceedings (other than the legal

costs of the parties) will be as agreed between the Claimants and summarised by the Adviser. Each party will bear its own legal costs.

DATED: 21 March 2017

40 See for example, Australian Securities and Investments Commission v Letten (No7) [2010] FCA 1231.41 See for example, Hannan v Zindilis [2016] VSC 723.42 See Hannan v Zindilis [2016] VSC 723, at paragraph 25.

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SCHEDULE 1 - CLAIMANTS

Affected Generator ABN Affected Generating System Classification DUID

AGL Hydro Partnership 86 076 691 481 Oaklands Hill Wind Farm Semi-Scheduled OAKLAND1

AGL Loy Yang Marketing Pty Ltd 19 105 758 316 Loy Yang A Power Station Scheduled LYA1, LYA2, LYA3 &

LYA4

AGL Macquarie Pty Ltd 18 167 859 494Bayswater Power Station Scheduled BW01, BW02, BW03 &

BW04

Liddell Power Station Scheduled LD02 & LD04

AGL SA Generation Pty Ltd 84 081 074 204

Torrens Island Power Station "A" Scheduled TORRA4

Torrens Island Power Station "B" Scheduled TORRB1 & TORRB4

Callide Power Trading Pty Limited 80 082 468 719 Callide Power Plant Scheduled CPP_3

CS Energy Limited 54 078 848 745

Callide B Power Station Scheduled CALL_B_1 & CALL_B_2

Gladstone Power Station ScheduledGSTONE1, GSTONE2,GSTONE3, GSTONE4,GSTONE5 & GSTONE6

Kogan Creek Power Station Scheduled KPP_1

EnergyAustralia Pty Ltd 99 086 014 968Mt Piper Power Station Scheduled MP2

Tallawarra Power Station Scheduled TALWA1

EnergyAustralia Yallourn Pty Ltd 47 065 325 224 Yallourn Power Station Scheduled YWPS1, YWPS2, YWPS3

& YWPS4

Hazelwood Power 40 924 759 557 Hazelwood Power Station ScheduledHWPS1, HWPS2, HWPS5, HWPS6, HWPS7 & HWPS8

Hydro-Electric Corporation (Trading as Hydro Tasmania)

48 072 377 158

Bastyan Power Station Scheduled BASTYAN

Catagunya/Liapootah/Wayatinah Power Station Scheduled LI_WY_CA

Cethana Power Station Scheduled CETHANA

Devil’s Gate Power Station Scheduled DEVILS_G

Gordon Power Station Scheduled GORDON

John Butters Power Station Scheduled JBUTTERS

Lemonthyme/Wilmot Power Station Scheduled LEM_WIL

Mackintosh Power Station Scheduled MACKNTSH

Poatina Power Station Scheduled POAT110 & POAT220

Reece Power Station Scheduled REECE1 & REECE2

Tarraleah Power Station Scheduled TARRALEA

Tribute Power Station Scheduled TRIBUTE

Tungatina Power Station Scheduled TUNGATIN

IPM Australia Limited 87 055 563 785 Loy Yang B Power Station Scheduled LOYYB1 & LOYYB2

Lake Bonney Wind Power Pty Ltd 48 104 654 837

Lake Bonney Stage 2 Wind Farm Semi-Scheduled LKBONNY2

Lake Bonney Stage 3 Wind Farm Semi-Scheduled LKBONNY3

Millmerran Energy Trader Pty Ltd 23 084 923 973 Millmerran Power Plant Scheduled MPP_2

Origin Energy Electricity Limited

33 071 052 287 Eraring Power Station Scheduled ER01, ER02, ER03 & ER04

Darling Downs Power Station Scheduled DDPS1

Mortlake Power Station Units Scheduled MORTLK11 & MORTLK12

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Affected Generator ABN Affected Generating System Classification DUID

Mt Stuart Power Station Scheduled MSTUART1

Osborne Power Station Scheduled OSB-AG

Quarantine Power Station Scheduled QPS4

Origin Energy Uranquinty Power Pty Ltd 26 120 384 938 Uranquinty Power Station Scheduled URANQ11 & URANQ13

Pelican Point Power Limited 11 086 411 814 Pelican Point Power Station Scheduled PPCCGT

Snowy Hydro Limited 17 090 574 431

Tumut 1 & 2 Power Station Scheduled UPPTUMUT

Tumut 3 Power Station Scheduled TUMUT3

Murray 1 & Murray 2 Power Station Scheduled MURRAY

Stanwell Corporation Limited 37 078 848 674

Barron Gorge Power Station Scheduled BARRON-1

Stanwell Power Station Scheduled STAN-1, STAN-2, STAN-3 & STAN-4

Tarong North Power Station Scheduled TNPS1

Tarong Power Station Scheduled TARONG#1, TARONG#3 & TARONG#4

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SCHEDULE 2 - GLOSSARY

TERM MEANING

Affected Generator Any Market Generator impacted by the scheduling error.

DRP dispute resolution panel

DUID Dispatchable unit ID

EST Eastern Standard Time

Generating Systems See paragraph 3.

MW megawatt

MWh megawatt hour

NEL National Electricity Law

NEMDE NEM dispatch engine

NSP Network Service Provider

Scheduling Error Period

See paragraph 4.

TNSP Transmission Network Service Provider

UIGF unconstrained intermittent generation forecast

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SCHEDULE 3 - SCHEDULING ERROR REPORT

http://www.aemo.com.au/-/media/Files/Electricity/NEM/Market_Notices_and_Events/Market_Event_Reports/2014/Incorrect-South-East-Tx-rating---13-29-December-2014_Republished_Final.pdf

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